Multi-vessel coil shooting acquisition

ABSTRACT

Methods for efficiently acquiring full-azimuth towed streamer survey data are described. The methods use multiple vessels to perform coil shooting.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.14/223,556 filed Mar. 24, 2014 and currently pending; which is acontinuation of U.S. patent application Ser. No. 12/650,268 filed Dec.30, 2009, now U.S. Pat. No. 8,681,580 issued Mar. 25, 2014; which is acontinuation in part of U.S. patent application Ser. No. 12/121,324filed May 15, 2008, now U.S. Pat. No. 8,559,265 issued Oct. 15, 2013.U.S. patent application Ser. No. 12/650,268 also claims the benefit of,and the present application herein claims the benefit of and priorityto, U.S. Provisional Patent Application Ser. Nos. 61/218,346 filed Jun.18, 2009 and 61/180,154 filed May 21, 2009. All of these applicationsare incorporated herein by reference in their entireties.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of marine survey dataacquisition methods. More specifically, the invention relates to methodsfor acquiring high quality long-offset, full-azimuth survey data.

2. Description of the Related Art

The performance of a marine seismic acquisition survey typicallyinvolves one or more vessels towing at least one seismic streamerthrough a body of water believed to overlie one or morehydrocarbon-bearing formations. WesternGeco L.L.C. currently conductshigh-resolution Q-Marine™ surveys, in some instances covering manysquare kilometers. In many areas of the world hydrocarbon reservoirslocated in structurally complex areas may not be adequately illuminatedeven with advanced towed marine streamer acquisition methods.

For example, the shallow, structurally complex St. Joseph reservoir offMalaysia produces oil and gas in an area that poses many surveying andimaging challenges. Strong currents, numerous obstructions andinfrastructure, combined with difficult near-surface conditions, mayhinder conventional survey attempts to image faults, reservoir sands,salt domes, and other geologic features.

A survey vessel known as a Q-Technology™ vessel may conduct seismicsurveys towing multiple, 1000-10,0000-meter cables with a separation of25-50 meters, using the WesternGeco proprietary calibrated Q-Marine™source. “Q” is the WesternGeco proprietary suite of advanced seismictechnologies for enhanced reservoir location, description, andmanagement. For additional information on Q-Marine™, a fully calibrated,point-receiver marine seismic acquisition and processing system, as wellas Q-Land™ and Q-Seabed™, see http://www.westerngeco.com/q-technology.

To achieve high density surveys in regions having a combination ofimaging and logistical challenges, a high trace density and closelyspaced streamers may be used. However, this presents the potential ofentangling and damaging streamer cables and associated equipment, unlessstreamer steering devices are closely monitored and controlled.Wide-azimuth towed streamer survey data is typically acquired usingmultiple vessels, for example: one streamer vessel and two sourcevessels; two streamer vessels and two source vessels; or one streamervessel and three source vessels. Many possible marine seismic spreadscomprising streamers, streamer vessels, and source vessels may beenvisioned for obtaining wide- or rich-azimuth survey data.

Assignee's co-pending application Ser. No. 11/335,365, filed Jan. 19,2006, discusses some of these. This document discusses shooting andacquiring marine seismic data during turns of linear marine surveys andduring curvilinear paths. While an advance in the art, the art continuesto seek improvements to marine seismic data acquisition techniques.

Cole et al., “A circular seismic acquisition technique for marine threedimensional surveys,” Offshore Technology Conference, OTC 4864, May 6-9,1985, Houston, Tex., described a concentric circle shooting scheme forobtaining three dimensional marine survey data around a sub-sea saltdome. While perhaps useful when the location of the feature is known,this technique would not be efficient or productive for finding new oiland gas deposits, or for monitoring changes in same if such informationis desired.

A great leap in acquisition technology was described in anotherassignee's co-pending application Ser. No. 12/121,324, filed on May 15,2008. This reference describes methods for efficiently acquiringwide-azimuth towed streamer seismic data, which is also known as the“coil shooting” technique.

While the Q suite of advanced technologies for marine seismic dataacquisition and processing may provide detailed images desired for manyreservoir management decisions, including the ability to acquire wide-and/or rich azimuth data, the ability to acquire higher quality marineseismic data with less cost, or to increase the fold while alsoincreasing the diversity of azimuth and offset, are constant goals ofthe marine seismic industry and would be viewed as advances in the art.

SUMMARY OF THE INVENTION

In a first aspect, a method of acquiring full-azimuth survey datacomprises: deploying a first marine vessel towing at least one sourceand one receiver streamer swath; and deploying a second marine vesseltowing at least one source; wherein the first marine vessel and secondmarine vessel travel along generally curved advancing paths whileacquiring survey data.

In a second aspect, a method, comprises: deploying a towed array marineseismic survey spread including: a seismic receiver array; andconducting a multi-vessel, coil shooting, towed array marine seismicsurvey. The seismic survey spread includes at least two seismic sources;and a plurality of survey vessels towing the seismic receiver array andthe seismic sources.

The above presents a simplified summary of the invention in order toprovide a basic understanding of some aspects of the invention. Thissummary is not an exhaustive overview of the invention. It is notintended to identify key or critical elements of the invention or todelineate the scope of the invention. Its sole purpose is to presentsome concepts in a simplified form as a prelude to the more detaileddescription that is discussed later.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention may be understood by reference to the followingdescription taken in conjunction with the accompanying drawings, inwhich like reference numerals identify like elements, and in which:

FIG. 1 conceptually illustrates in a “bird's eye” view one particularembodiment of a multi-vessel towed array, marine seismic survey using acoil shoot implemented in accordance with one aspect of the presentinvention;

FIG. 2A-FIG. 2B depict selected spread elements of the spread firstshown in FIG. 1 of a streamer array first shown in FIG. 1, including astreamer survey vessel, a plurality of streamers, seismic sensors, and aseismic source in a plan, overhead view;

FIG. 3A-FIG. 3B depict a streamer only survey vessel and a source onlysurvey vessel, respectively, such as may be used in some aspects ofvarious embodiments;

FIG. 4 illustrates selected portions of the survey first shown in FIG.1;

FIG. 5 is the offset-azimuth distribution for data acquired in theembodiment of FIG. 1;

FIG. 6 conceptually illustrates in a “bird's eye” view a secondembodiment of a multi-vessel towed array, marine seismic survey using acoil shoot implemented in accordance with one aspect of the presentinvention;

FIG. 7 is the offset-azimuth distribution for data acquired in theembodiment of FIG. 6;

FIG. 8 conceptually illustrates in a “bird's eye” view a secondembodiment of a multi-vessel towed array, marine seismic survey using acoil shoot implemented in accordance with one aspect of the presentinvention;

FIG. 9 is the offset-azimuth distribution for data acquired in theembodiment of FIG. 8;

FIG. 10 is an exemplary from a simulation of the embodiment of FIG. 1;

FIG. 11A-FIG. 11C illustrate design considerations for use in planning amulti-vessel coil shoot;

FIG. 12 illustrates a controlled sources electromagnetic survey,according to one particular embodiment; and

FIG. 13A-FIG. 13B compare the illumination of a steep-dip subsaltreservoir with a two streamer vessel, four source vessel (six sources)wide azimuth parallel geometry acquisition and with a two streamervessel, four source vessel (six sources) coil shooting acquisition.

While the invention is susceptible to various modifications andalternative forms, the drawings illustrate specific embodiments hereindescribed in detail by way of example. It should be understood, however,that the description herein of specific embodiments is not intended tolimit the invention to the particular forms disclosed, but on thecontrary, the intention is to cover all modifications, equivalents, andalternatives falling within the spirit and scope of the invention asdefined by the appended claims.

DETAILED DESCRIPTION

One or more specific embodiments of the present invention will bedescribed below. It is specifically intended that the present inventionnot be limited to the embodiments and illustrations contained herein,but include modified forms of those embodiments including portions ofthe embodiments and combinations of elements of different embodiments ascome within the scope of the following claims. It should be appreciatedthat in the development of any such actual implementation, as in anyengineering or design project, numerous implementation-specificdecisions must be made to achieve the developers' specific goals, suchas compliance with system-related and business related constraints,which may vary from one implementation to another. Moreover, it shouldbe appreciated that such a development effort might be complex and timeconsuming, but would nevertheless be a routine undertaking of design,fabrication, and manufacture for those of ordinary skill having thebenefit of this disclosure.

In the following description, numerous details are set forth to providean understanding of the present invention. However, it will beunderstood by those skilled in the art that the present invention may bepracticed without these details and that numerous variations ormodifications from the described embodiments may be possible. Forexample, in the discussion herein, aspects of the invention aredeveloped within the general context of acquiring high quality marineseismic data in a more cost efficient manner, which may employcomputer-executable instructions, such as program modules, beingexecuted by one or more conventional computers. Generally, programmodules include routines, programs, objects, components, datastructures, etc., that perform particular tasks or implement particularabstract data types.

Moreover, those skilled in the art will appreciate that the inventionmay be practiced in whole or in part with other computer systemconfigurations, including hand-held devices, personal digitalassistants, multiprocessor systems, microprocessor-based or programmableelectronics, network PCs, minicomputers, mainframe computers, and thelike. In a distributed computer environment, program modules may belocated in both local and remote memory storage devices. It is noted,however, that modification to the systems and methods described hereinmay well be made without deviating from the scope of the presentinvention. Moreover, those skilled in the art will appreciate, from thediscussion to follow, that the principles of the invention may well beapplied to other aspects of seismic data acquisition. Thus, the systemsand method described below are but illustrative implementations of abroader inventive concept.

The present invention relates to methods for efficiently acquiringmarine seismic data, wherein efficiency may be defined as more costeffective in that less seismic resources are used. It also providesimproved seismic imaging using minimal marine seismic equipment (onlyone vessel is required, although an additional source vessel may beused, as explained more fully herein). Furthermore, a richer azimuthsurvey can be acquired than what is acquired with systems and methodsemployed to date that are based on parallel acquisition geometryconcept.

The systems and methods of the invention may be particularly adept atacquiring wide- and/or rich azimuth marine seismic data, and acquiringsuch data while traversing generally curved advancing paths, which maybe characterized as coil patterns or paths. When viewed in plan view,certain paths useful in the invention may resemble overlapping circles,as in a flattened coil. The time to shoot a survey may be longer withthe inventive methods compared to traditional linear surveys. If thesame survey can be acquired with a four vessel configuration sailinggenerally parallel the total time required may be shorter; however thetotal cost is higher for multiple vessel marine seismic dataacquisition, and multiple vessels are not always available.

A distinct feature of the inventive methods is that the azimuth ischanging from shot to shot. This excludes redundancy in the azimuthsacquired, whereas conventional marine acquisition is based on parallelacquisition geometry and this implies azimuth redundancy. A widerazimuth range can be acquired with parallel geometry by adding extravessels or by repeating the survey with different cross-line offsets,however both of these options add to the cost of the seismic survey.

Other possible benefits of methods of the present invention include:

-   -   a line change is required only for data management reasons,        otherwise the survey may be acquired continuously;    -   high efficiency data acquisition: the line change is in the        order of few minutes;    -   the azimuths are different from shot to shot;    -   rich azimuth-and offset distribution data is collected;    -   very high fold is acquired;    -   coil shooting methods of the invention are less sensitive to        currents;    -   no infill or a minimum amount of infill is required;    -   the coil shooting methods are less sensitive to seismic        interferences;    -   the effect of perturbations due to the obstructions may be less        than for multiple-vessel, linear wide-azimuth acquisition; and    -   the methods offer improved reservoir illumination (including,        but not limited to, sub-salt reservoir illumination) and more        effective coherent noise attenuation due to the high variability        of azimuths.        Note that not all embodiments will necessarily exhibit all of        the benefits discussed herein. To the extent that various        embodiments manifest some of the benefits, not all of them will        exhibit them to the same degree.

A rich- or wide-azimuth towed streamer survey may be acquired inaccordance with the present invention using a single streamer vesselcomprising multiple streamers and a minimum of one source array. Incertain embodiments the methods include positioning of streamers and/orsources employing positioning apparatus or systems (for examplesatellite-based systems), one or more streamer steering devices, one ormore source array steering devices, and/or one or more noise attenuationapparatus or systems. One system, known as Q-Marine™ includes thesefeatures and may be useful in methods of the invention.

The coil shooting is generally described in more detail in assignee'sco-pending U.S. application Ser. No. 12/121,324, filed on May 15, 2008,which is incorporated herein by reference in its entirety. Note,however, that the embodiments disclosed therein are single vesseltechniques. Single vessel coil shooting is a very economical andefficient way of acquiring full-azimuth survey data. But the offsetamong the data may be limited by the lengths of the streamers.

For acquisition of long offset data, improved efficiency and betterdistribution of shots, multi-vessel methods as described below may beused. Multi-vessel configuration can be used to acquire coil shootingdata. Examples of multi-vessel configuration that can be used for coilshooting are:

-   -   2 receiver vessels and two source vessels or 2×4, depicted in        FIG. 1;    -   1 receiver vessel and three source vessels or 1×4, shown in FIG.        6; and    -   two receiver vessels (dual coil) or 2×2, depicted in FIG. 8.        Each of these embodiments will be discussed further below.

Turning now to the drawings, FIG. 1 conceptually illustrates oneparticular embodiment of a multi-vessel, towed array, marine seismicsurvey spread 100 implemented in accordance with one aspect of thepresent invention. The spread 100 comprises four survey vessels 111-114,two streamer arrays 121-122, and a plurality of sources 131-134. Thevessels 111, 114 are “receiver vessels” in that they each tow arespective one of the streamer arrays 121, 122, although they also tow arespective source 131, 134. Because they also tow the sources 131, 134,the receiver vessels 111, 114 are sometimes called “streamer/source”vessels or “receiver/source” vessels. In some embodiments, the receivervessels may omit the sources 131, 134. In such embodiments, the receivervessels are sometimes called “streamer only” vessels because they onlytow streamers. The vessels 112-113 are “source vessels” in that theyeach tow a respective source or source array 131-135 but no streamerarrays, that is they two the seismic sources 132-133 to the exclusion ofany streamer arrays. The vessels 112-113 are therefore sometimes called“source only” vessels.

Each streamer array 121, 122 comprises a plurality of streamers 140(only one indicated). The present invention admits wide variation in theimplementation of the streamers 140. As will be discussed further below,the streamers 140 are “multicomponent” streamers as will be discussedfurther below. Examples of suitable construction techniques may be foundin U.S. Pat. No. 6,477,711, U.S. Pat. No. 6,671,223, U.S. Pat. No.6,684,160, U.S. Pat. No. 6,932,017, U.S. Pat. No. 7,080,607, U.S. Pat.No. 7,293,520, and U.S. application Ser. No. 11/114,773, incorporated byreference below. Any of these alternative multicomponent streamers maybe used in conjunction with the presently disclosed technique. However,the invention is not limited to use with multicomponent streamers andmay be used with conventional, pressure-only streamers used in 2Dsurveys.

To further an understanding of the present invention, one particularembodiment of the streamer arrays will now be disclosed with respect toFIG. 2A-FIG. 2B. FIG. 2A depicts one particular embodiment of the surveyvessel 111, streamer array 121, and seismic source 131 in a plan,overhead view. On board the survey vessel 111 is a computing apparatus200. The computing apparatus 200 controls the streamer array 121 and thesource 131 in a manner well known and understood in the art. The towedarray 121 comprises ten streamers 140 (only one indicated). The numberof streamers 140 in the towed array 121 is not material to the practiceof the invention. These aspects of the apparatus may be implemented inaccordance with conventional practice.

At the front of each streamer 140 is a deflector 206 (only oneindicated) and at the rear of every streamer 140 is a tail buoy 209(only one indicated) used to help control the shape and position of thestreamer 140. Located between the deflector 206 and the tail buoy 209are a plurality of seismic cable positioning devices known as “birds”212. In this particular embodiment, the birds 212 are used to controlthe depth at which the streamers 140 are towed, typically a few meters.

The streamers 140 also include a plurality of instrumented sondes 214(only one indicated) distributed along their length. The instrumentedsondes 214 house, in the illustrated embodiment, an acoustic sensor 220(e.g., a hydrophone) such as is known to the art, and a particle motionsensor 223, both conceptually shown in FIG. 2B. The particle motionsensors 223 measure not only the magnitude of passing wavefronts, butalso their direction. The sensing elements of the particle motionssensors may be, for example, a velocity meter or an accelerometer.

The sensors of the instrumented sondes 214 then transmit datarepresentative of the detected quantity over the electrical leads of thestreamer 140 to the computing apparatus 200. The streamer 140 in thisparticular embodiment provides a number of lines (i.e., a power lead226, a command and control line 229, and a data line 232) over whichsignals may be transmitted. Furthermore, the streamer 140 will alsotypically include other structures, such as strengthening members (notshown), that are omitted for the sake of clarity.

The inline separation of the streamer components and the crosslineseparation of the streamers will be determined in accordance withtechniques well known in the art in view of implementation specificrequirements for the survey to be conducted.

Returning to FIG. 1, the sources 131-134 typically will be implementedin arrays of individual sources. The sources 131-134 may be implementedusing any suitable technology known to the art, such as impulse sourceslike explosives, air guns, and vibratory sources. One suitable source isdisclosed in U.S. Pat. No. 4,657,482, incorporated by reference below.The embodiment illustrated in FIG. 1 simultaneously shoots several ofthe sources 131-134. Accordingly, care should be taken so that thesources 131-137 can be separated during subsequent analysis. There are avariety of techniques known to the art for source separation and anysuch suitable technique may be employed. Source separation may beachieved by a source encoding technique in which one source is coherentand another source is incoherent in a certain collection domain, such ascommon depth point, common receiver or common offset. Another way sourceseparation technique is disclosed in C. Beasley & R. E. Chambers, 1998,“A New Look at Simultaneous Sources,” 60^(th) Conference and Exhibition,EAGE, Extended Abstracts, 02-38.

As was noted above, some receiver vessels (e.g., “streamer only” vesselsor “receiver only” vessels) may omit the sources 131, 134 and the sourcevessels 112-113 tow only sources. FIG. 3A illustrates a receiver onlyvessel 300 and FIG. 3B illustrates a source only vessel 310 towing aseismic source 312.

The relative positions of the vessels 111-114 described above, as wellas the shape and depth of the streamers 140, may be maintained whiletraversing the respective sail lines 171-174 using control techniquesknown to the art. Any suitable technique known to the art may be used.Suitable techniques includes those disclosed in U.S. Pat. No. 6,671,223,U.S. Pat. No. 6,932,017, U.S. Pat. No. 7,080,607, U.S. Pat. No.7,293,520, and U.S. application Ser. No. 11/114,773, incorporated byreference below.

The illustrated embodiment uses WesternGeco Q-Marine technology thatprovides features such as streamer steering, single-sensor recording,large steerable calibrated source arrays, and improved shotrepeatability, as well as benefits such as better noise sampling andattenuation, and the capability to record during vessel turns, allcontribute to the improved imaging. More particularly, each of thevessels 111-114 is a Q™ vessel owned and operated by WesternGeco, theassignee hereof. Each vessel 111-114 is provided with a GPS receivercoupled to an integrated computer-based seismic navigation (TRINAV™),source controller (TRISOR™), and recording (TRIACQ™) system(collectively, TRILOGY™), none of which are separately shown. Thesources 131-134 are typically TRISOR™-controlled multiple air gunsources.

The above is but one exemplary embodiment. The spread 100 may beimplemented using any technology suitable to the art. The one caveat isthat the spread controllers in the spread must be capable of controllingthe position of the spread elements during the acquisition describedbelow. One advantage of using the Q-Marine technology is that itprovides superior control relative to most other implementations in theart.

FIG. 4 is a “snapshot” during the acquisition described above for thevessel 111 as it traverses its respective sail line 171. For the sake ofclarity, and so as not to obscure this aspect of the invention, somedetail is omitted. For example, only the receiver vessel 111, streamerarray 121, and source 131 are shown because the operation of the otherspread elements can readily be extrapolated therefrom. Some elements ofthe streamer 140, namely the positioning devices, are likewise omittedfor the same reason.

FIG. 4 also shows a subterranean geological formation 430. Thegeological formation 430 presents a seismic reflector 445. As those inthe art having the benefit of this disclosure will appreciate,geological formations under survey can be much more complex. Forinstance, multiple reflectors presenting multiple dipping events may bepresent. FIG. 4 omits these additional layers of complexity for the sakeof clarity and so as not to obscure the present invention.

Still referring to FIG. 4, the seismic source 131 generates a pluralityof seismic survey signals 425 in accordance with conventional practiceas the survey vessel 111 tows the streamers 140 across the area to besurveyed in predetermined coil pattern described above. The seismicsurvey signals 425 propagate and are reflected by the subterraneangeological formation 430. The receivers 214 detect the reflected signals435 from the geological formation 430 in a conventional manner. Thereceivers 214 then generate data representative of the reflections 435,and the seismic data is embedded in electromagnetic signals.

The signals generated by the receivers 214 are communicated to the datacollection unit 200. The data collection unit 200 collects the seismicdata for subsequent processing. The data collection unit 200 may processthe seismic data itself, store the seismic data for processing at alater time, transmit the seismic data to a remote location forprocessing, or some combination of these things.

The survey of FIG. 1 is a wide-azimuth survey. The offset-azimuth plotfor this survey is illustrated in FIG. 5.

The invention admits variation in its implementation of not only thespread elements, but the spread itself and the design of the survey.FIG. 6 depicts an alternative embodiment 600 employing a single receivervessel 605 and three source vessels 610. Note that, in this embodiment,all the vessels 605, 610 tow a source 615 while only the receiver vessel605 tows a streamer array 630. The offset-azimuth plot for theembodiment 600 is shown in FIG. 7. Note that the sail lines 621-623,shown in FIG. 6, form three concentric circles. This may be referred toas a 1×4 coil shoot because there is one streamer array and foursources.

FIG. 8 depicts a third embodiment 800 using two receiver vessels 805,each towing a respective source 810 and a respective streamer array 830,on offset sail lines 821-822. This is a “dual coil” pattern, or a 2×2coil shoot. The offset-azimuth plot for the embodiment 800 is shown inFIG. 9. Still other alternative embodiments may become apparent to thoseskilled in the art.

Multi-vessel coil shooting such as that described above providescollection of longer offsets and improved efficiency. From theoffset-azimuth diagrams presented in FIG. 5, FIG. 7, and FIG. 9, one cansee that offsets longer than 12 km and full azimuth can be acquired.Multi-vessel coil shooting also allows larger interval between circlesthan does single vessel coil shooting. For instance, if for singlevessel coil shooting the interval between circles (circle roll) is 1200m, for dual coil shooting acquisition the circle roll could be 1800 m inx and y directions, and this will reduce the total number of days forthe acquisition.

As will be apparent to those skilled in the art from the disclosureherein, the shot distribution from multi-vessel coil shooting is notalong one single circle as in single vessel coil shooting, but alongmultiple circles. The maximum number of circles is equal to the numberof vessels. The pattern of shot distribution is nearly random and thisis a benefit for imaging and multiple attenuation. An example of shotdistribution from simulation of a 2×2 coil shooting acquisition ispresented in FIG. 9.

In each of FIG. 1, FIG. 6, and FIG. 8, only a single set of sail linesis shown. Those in the art will appreciate that the survey areas aretypically rather larger, and that a single set of sail lines will beinsufficient to cover an entire survey area. Accordingly, preparationfor the survey will typically involve the planning of multiple, circularsail lines. This can be adapted from techniques used in single vesselcoil shooting as disclosed in U.S. application Ser. No. 11/335,365,filed Jan. 19, 2006, and incorporated below.

Design parameters for multi-vessel coil shooting include: the number ofstreamers; the streamer separation; the streamer length; the circleradius, the circle roll in X and Y directions; the number of vessels;and the relative location of the vessels relative to a master vessel.These parameters are selected to optimize: data distribution inoffset-azimuths bins or in offset-vector tiles; and cost efficiency.Those skilled in the art having the benefit of this disclosure willappreciate that these factors can be combined in a number of ways toachieve the stated goals depending upon the objective of and theconstraints on the particular survey. Their application will thereforebe implementation specific.

As noted above, one particular consideration in a multivessel coil shootis how the vessels are positioned relative to a master vessel. Themaster vessel is one of the streamer vessels. One factor in thisconsideration is the position of the source vessel relative to thestreamer vessel; in FIG. 1, the source vessels were placed behind thestreamer vessels; this arrangement will generate positive and negativeoffsets (or “split-spread” type data). Other factors include the circleradii of the source vessels and the position of the second streamervessel vs. the master vessel. The offset and azimuth distribution formultivessels coil shooting is determined d by these factors.

To speed up the acquisition for a coil shoot, one may use two streamervessels separated by certain distance. However, we do not have thebenefit of a wider footprint and offset-azimuth distribution that isacquired with multivessel acquisition. Also, single vessel acquisitioncan use also an additional source vessel but this is mostly used toundershoot isolated obstructions

FIG. 11A-FIG. 11B show how the offset azimuth bins and offset-vectortiles are defined. The objective of survey design is to have a uniformdata distribution that will allow applying the appropriate processingsequence in these domains. FIG. 11C shows an example of datadistribution for an offset range of 400 m to 600 m and azimuth range0-45° for a 2×4 coil shooting acquisition.

Multi-vessel coil shooting allows more flexibility in survey design thana single vessel coil shooting. Depending on the survey objectives, i.e.,if the survey is a reservoir development type or an exploration typesurvey the roll interval can vary. For an exploration type survey theroll interval is larger than the roll interval for a development typesurvey due to the fact that for multi-vessel coil shooting the shots aredistributed on several circles and this generates a larger subsurfacefootprint, which allows to increase the roll interval. In this way thedata density and the cost-efficiency could be balanced to accommodatethe survey objectives.

Table-1 shows a comparison between a single coil shooting survey, a dualcoil shooting survey and a 2×4 coil shooting survey in terms of rollinterval in X and Y directions, data density and total number of daysrequired to acquire a survey that covers an area of 30 km×30 km. Thenumber of days represents 100% production time.

TABLE 1 Comparison Between Different Coil Shooting Design Options & 2 ×4 RAZ for an area of 30 km × 30 km No. of Configuration Roll Circles No.of Shots No. of Days Single Coil 1400 m 484 507,232 (5,600 tr/s)  103Dual Coil 1800 m 256 268,288 (11,200 tr/s)  55 2 × 4 coil 2400 m 169177,112 (112,200 tr/s) 37

Most towed marine streamers are used in seismic surveys. The towedmarine streamers may also be used in other types of surveys, forexample, Controlled Sources Electromagnetic surveys (“CSEM”). In a CSEMsurvey at least one “vertical” electromagnetic (EM) source is towed by amarine vessel. EM receivers are also towed by either the same marinevessel or by a different marine vessel. In this manner, the EM source istowed along with the EM receivers through a body of water to performCSEM surveying.

FIG. 12 shows an exemplary marine survey arrangement that includes amarine vessel 1200 that tows an assembly 1202 of a vertical EM source1204 (made up of source electrodes 1234 and 1236), electric fieldreceivers (made up of electrodes 1240, 1242, 1244, 1246, 1250, 1252,1254, and 1256), and magnetometers 1208. The electric field receiversare used to measure electric fields. The magnetometers 1208 (either1-2-3 components or total field magnetometers) are used to measuremagnetic fields. The magnetometers 1208 can be used to measure themagnetic fields at various offsets. The electric field receivers andmagnetometers collectively are considered EM receivers (for measuringboth electrical and magnetic fields).

The electrical cable 1230 includes a first source electrode 1234, andthe cable 1232 includes a second source electrode 1236, where the sourceelectrodes 1234 and 1236 are spaced apart by the distance D. The sourceelectrodes 1234 and 1236 are part of the vertical EM source 1204. Thesource electrodes 1234 and 1236 are aligned above and below each othersuch that when a current is passed between them (with the direction ofcurrent flow depicted with double arrows 1238), a vertical electricdipole is created.

In operation, as the marine vessel 1200 tows the assembly 1202 throughthe body of water 1214, the controller 1224 can send commands to theelectronic module 1210 to cause activation of the vertical EM source1204. Activation of the vertical EM source 1204 causes EM fieldsaccording to the TM mode to be generated and to be propagated into thesubterranean structure 1220. EM signals that are affected by thesubterranean structure 1220 are detected by the electric field receiversand the magnetometers 1208 of the assembly 1202. As noted above, theelectric field receivers made up of the receiver electrodes 1240, 1242,1244, 1246, 1250, 1252, 1254, and 1256 measure the electric fields, withreceiver electrodes along each cable measuring horizontal electricfields, and two vertically spaced receiver electrodes on respectivecables 1230 and 1232 measuring vertical electric fields. Also, themagnetometers 1208 measure magnetic fields.

The multi-vessel coil shoot survey disclosed herein can also be employedin a CSEM survey such as that described above. One example of a CSEMstreamer is disclosed and claimed in U.S. application Ser. No.12/174,179, filed Jul. 15, 2008, incorporated by reference below.

Typical benefits of multivessel coil shooting such as is disclosedherein include:

-   -   improved subsurface illumination due to the long offsets (up to        14 km) and full-azimuth data acquired;    -   near offsets and far offset are acquired from each shot;    -   improved multiple attenuation due to larger offsets;    -   improved cost efficiency due to a larger roll interval;    -   high density data can be acquired by using simultaneous sources;        note: if 4 sources are available and all 4 shoot simultaneously        the data density is increased 4× vs. sequential shooting;    -   enables subsalt AVO analysis due to the fact that larger angles        of incidence are acquired; note: longer offsets increases the        angle of incidence for the subsalt sediments; and    -   easy to undershoot isolated obstructions.        Note that not all embodiments will manifest each of these        benefits to the same degree. Indeed, some embodiments may not        exhibit all of these benefits, omitting some of them in        particular implementations. Conversely, those skilled in the art        may appreciate benefits and advantages in addition to those set        forth above.

For example, consider FIG. 13A-FIG. 13B. FIG. 13A-FIG. 13B compare theillumination of a steep-dip subsalt reservoir with a two streamervessel, four source vessel (six sources) wide azimuth parallel geometryacquisition and with a two streamer vessel, four source vessel (sixsources) coil shooting acquisition, respectively. That is, FIG. 13B canbe acquired using the embodiment of FIG. 1. These drawings are “hitmaps,” wherein coloration/shading represent the number hits per bin, andwere derived based on ray tracing. It could be seem that theillumination of the steep-dip subsalt reservoirs requires long offsetand full azimuth data. In FIG. 13A, the maximum offset was 8600 mwherein the maximum offset in FIG. 13B was 14000 m.

Thus, in accordance with the present invention, methods are describedfor acquiring marine seismic data that may be more cost effective andprovide improved seismic imaging compared to presently employed methods.Methods of the invention comprise acquiring wide- or rich-azimuth datausing a single streamer vessel (in certain embodiments using a singleQ-Technology™ streamer vessel) towing multiple streamer cables using oneor more calibrated marine seismic sources (in certain embodimentsQ-Marine™ sources), wherein the streamer vessel and the one or moresource arrays traverse a generally curved advancing shooting pattern. Incertain embodiments one or more source arrays may traverse a smaller orlarger curved pattern than the streamer vessel.

As used herein the phrase “generally curved advancing path” means thatthe vessels and streamers travel generally in a curve, and there is anadvancement in one or more of the X and Y directions, as explainedfurther herein. The path may be expressed as a coil. The curve may becircular, oval, elliptical, FIG. 8, or other curved path. Generally,multiple vessels having sources are used in various configurations, forexample:

-   -   1×3 (one vessel has streamers, three vessels have sources),    -   2×2 (two vessels total, each have streamers and sources),    -   2×4 (two vessels have streamers and four have sources).        Those in the art having the benefit of this disclosure will        realize additional alternative embodiments by which the        invention may be disclosed.

Although only a few exemplary embodiments of this invention have beendescribed in detail above, those skilled in the art will readilyappreciate that many modifications are possible in the exemplaryembodiments without materially departing from the novel teachings andadvantages of this invention. Accordingly, all such modifications areintended to be included within the scope of this invention as defined inthe following claims. In the claims, no clauses are intended to be inthe means-plus-function format allowed by 35 U.S.C. §112, ¶6 unless“means for” is explicitly recited together with an associated function.“Means for” clauses are intended to cover the structures describedherein as performing the recited function and not only structuralequivalents, but also equivalent structures.

As used herein, the phrase “capable of” as used herein is a recognitionof the fact that some functions described for the various parts of thedisclosed apparatus are performed only when the apparatus is poweredand/or in operation. Those in the art having the benefit of thisdisclosure will appreciate that the embodiments illustrated hereininclude a number of electronic or electro-mechanical parts that, tooperate, require electrical power. Even when provided with power, somefunctions described herein only occur when in operation. Thus, at times,some embodiments of the apparatus of the invention are “capable of”performing the recited functions even when they are not actuallyperforming them—i.e., when there is no power or when they are poweredbut not in operation.

The following documents are hereby incorporated by reference for thenoted teaching as if set forth herein verbatim:

-   -   U.S. Pat. No. 4,757,482, entitled, “Modular Airgun Array Method,        Apparatus and System,” and issued Jul. 12, 1988, to Bolt        Technology Corporation, as assignee of the inventor Augustus H.        Fiske, Jr. for its teachings seismic source design and        construction;    -   U.S. Pat. No. 6,477,711, entitled, “Method of Making a Marine        Seismic Streamer,” and issued Nov. 5, 2002, to Schlumberger        Technology Corporation, as assignee of the inventors Lunde et        al., for its teachings regarding streamer design and        construction;    -   U.S. Pat. No. 6,671,223, entitled, “Control Devices for        Controlling the Position of a Marine Seismic Streamer,” and        issued Dec. 30, 2003, to WesternGeco, LLC, as assignee of the        inventor Simon Hastings Bittleston, for its teachings regarding        streamer design and construction as well as its teachings about        spread control;    -   U.S. Pat. No. 6,684,160, entitled, “Marine Seismic Acquisition        System and Method,” and issued Jan. 27, 2004, to WesternGeco,        LLC, as assignee of the inventors Ösbek et al., for its        teachings regarding streamer design and construction;    -   U.S. Pat. No. 6,932,017, entitled, “Control System for        Positioning of Marine Seismic Streamers,” and issued Aug. 23,        2005, to WesternGeco, LLC, as assignee of the inventors Øyvind        Hillesund and Simon Bittleston for its teachings regarding        streamer design and construction as well as its teachings about        spread control;    -   U.S. Pat. No. 7,080,607, entitled, “Seismic Data Acquisition        Equipment Control System,” and issued Jul. 25, 2006, to        WesternGeco LLC, as assignee of the inventors Øyvind Hillesund        and Simon Bittleston for its teachings regarding streamer design        and construction as well as its teachings about spread control;    -   U.S. Pat. No. 7,293,520, entitled, “Control System for        Positioning of Marine Seismic Streamers,” and issued Nov. 13,        2007, to WesternGeco LLC, as assignee of the inventors Øyvind        Hillesund and Simon Bittleston for its teachings regarding        streamer design and construction as well as its teachings about        spread control;    -   U.S. application Ser. No. 11/114,773, entitled, “Seismic        Streamer System and Method,” and filed Apr. 26, 2005, in the        name of the inventors Singh et al. for its teachings regarding        multicomponent streamer design, construction and operation;    -   U.S. application Ser. No. 11/335,365, entitled, “Methods and        Systems for Efficiently Acquiring Towed Streamer Seismic        Surveys,” and filed Jan. 19, 2006, in the name of the inventors        Nicolae Moldoveanu and Steven Fealy for its teachings regarding        the design of circular, coil shoot sail lines;    -   U.S. application Ser. No. 12/351,156, entitled, “Acquiring        Azimuth Rich Seismic Data in the Marine Environment Using a        Regular Sparse Pattern of Continuously Curved Sail Lines,” and        filed Jan. 9, 2009, in the name of the inventors Hill et al.,        for its teachings regarding the design of circular, coil shoot        sail lines;    -   U.S. application Ser. No. 12/121,324, entitled “Methods for        Efficiently Acquiring Wide-Azimuth Towed Streamer Seismic Data,”        and filed on May 15, 2008, in the name of the inventors Nicolae        Moldoveanu and Steven Fealy for its teachings regarding the        design of circular, coil shoot sail lines; and    -   U.S. application Ser. No. 12/174,179, entitled “Surveying Using        Vertical Electromagnetic Sources that are Towed Along with        Survey Receivers,” and filed on Jul. 15, 2008, in the name of        the inventors Alumbaugh et al., for its teachings regarding CSEM        surveys; and    -   U.S. Provisional Patent Application Ser. No. 61/180,154,        entitled “Multi-Vessel Coil Shooting Acquisition,” and filed May        21, 2009, in the name of the inventors Nicolae Moldoveanu and        Steven Fealy, for all its teachings;    -   U.S. Provisional Patent Application Ser. No. 61/218,346,        entitled “Multi-Vessel Coil Shooting Acquisition,” and filed        Jun. 18, 2009, in the name of the inventors Nicolae Moldoveanu        and Steven Fealy, for all its teachings;    -   Beasley, C, J & R. E., Chambers, 1998, “A New Look at        Simultaneous Sources,” 60^(th) Conference and Exhibition, EAGE,        Extended Abstracts, 02-38, for its teachings regarding source        separation techniques.

This concludes the detailed description. The particular embodimentsdisclosed above are illustrative only, as the invention may be modifiedand practiced in different but equivalent manners apparent to thoseskilled in the art having the benefit of the teachings herein.Furthermore, no limitations are intended to the details of constructionor design herein shown, other than as described in the claims below. Itis therefore evident that the particular embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the invention. Accordingly, the protection soughtherein is as set forth in the claims below.

What is claimed is:
 1. A marine seismic acquisition system, comprising:a first vessel having a seismic streamer array disposed thereon; and oneor more controllers programmed to cause the first vessel to travel alonga first coil path during a multivessel coil shoot; wherein themultivessel coil shoot comprises an acquisition configuration having asecond vessel travelling along a second coil path.
 2. The marine seismicacquisition system of claim 1, wherein the first vessel includes aseismic source disposed thereon.
 3. The marine seismic acquisitionsystem of claim 1, wherein the second vessel has a seismic source. 4.The marine seismic acquisition system of claim 1, wherein the center ofthe first coil path is at an offset from the center of the second coilpath.
 5. The marine seismic acquisition system of claim 1, wherein thefirst coil path and the second coil path are different.
 6. The marineseismic acquisition system of claim 1, wherein the first coil path andthe second coil path are substantially the same.
 7. The marine seismicacquisition system of claim 1, wherein the second vessel travels aheadof the first vessel.
 8. The marine seismic acquisition system of claim1, wherein the multivessel coil shoot collects full azimuth seismicdata.
 9. A marine seismic acquisition system, comprising: a first vesselhaving a seismic source disposed thereon; and one or more controllersprogrammed to cause the first vessel to travel along a first coil pathduring a multivessel coil shoot; wherein the multivessel coil shootcomprises an acquisition configuration having a second vessel travellingalong a second coil path.
 10. The marine seismic acquisition system ofclaim 9, wherein the first vessel comprises a seismic streamer arraydisposed thereon.
 11. The marine seismic acquisition system of claim 9,wherein the second vessel travels behind the first vessel.
 12. Themarine seismic acquisition system of claim 11, wherein the second vesselcomprises a seismic streamer disposed thereon.
 13. The marine seismicacquisition system of claim 9, wherein the first coil path and thesecond coil path are different.
 14. The marine seismic acquisitionsystem of claim 9, wherein the center of the first coil path and thecenter of the second coil path are at an offset.
 15. The marine seismicacquisition system of claim 9, wherein the first coil path and thesecond coil path are substantially the same.
 16. The marine seismicacquisition system of claim 9, wherein the multivessel coil shootcollects full azimuth seismic data.